Drilling with low water content water in oil emulsion fluids



v United States Patent Fischer r 252/8.5(M)UX l75/66 2,550.054 4/1951 3,140,747 7/ l 964 Mitacek OTHER REFERENCES Perry, John H. Chemical Engineers Handbook. N.Y., Mc- Graw-Hill, 3D Ed., 1950, pp.9l4 and 1004.1Copy in Group l70) Uren. Lester C. Petroleum Production Engineering: Oil Field Development. N.Y.,McGraw-Hill, 4th Ed.. I956. pp.27928 1. (Copy in Group 350) Primary Examiner- Marvin A. Champion A ssislunt Examiner- Ian A. Calvert Attorneys-James A. Reilly. John B. Davidson, Lewis H. Eatherton and James E. Reed ABSTRACT: Shaley earth formations are drilled with reduced difficulty through the use of low water content water-in-oil invert emulsion fluids The water content of an oil base fluid containing dispersed water is controlled to prevent damage to water-sensitive shale formations by removing excess water from the drilling fluid.

Patented Oct. 13, 1970 3,533,480

Sheet of 2 LINEAR ELONGATION AFTER IO HOURS I l 0 IO 20 3O 4O 50 WATER CONTENT "/o 23 MARTIN E. CHENEVERT INVENTORS JOSEPH A. POLASEK AT TORNEY Sheet 2 of 2 I I I I I LINEAR ELONGATION AFTER l0 HOURS 6 MARTIN E. CHENEVERT INVENTORS JOSEPH A. POLASEK A TTORNEY DRILLING WITH LOW WATER CONTENT WATER IN OIL EMULSION FLUIDS BACKGROUND OF THE INVENTION l. Field of the Invention This invention is directed primarily to drilling wells through water-sensitive earth formations. More particularly, the inve ntion is concerned with methods for controlling the water content of water-in-oil emulsion drilling fluids to enable watersensitive earth formations to be drilled with a minimum of difficulty.

2. Description of the Prior Art The problems encountered in drilling through shales and similar water-sensitive formations are of long standing in the petroleum industry. Such problems are particularly acute in deep formations containing hard' shales but are also troublesome in shallower formations. The nature and extent of the difficulties encountered depend in part upon the characteristics of the particular water-sensitive formation to be penetrated. Such formations normally contain fine-grained argillaceous materials which in a compressed state have very low permeabilities, generally less than 0.001 millidarcy. Since such materials may have been deposited under widely different circumstances and subsequently subjected to different temperature and pressure conditions, water-sensitive formations may have mineral compositions and water contents which vary considerably.

Water-sensitive shale formations are broadly categorized in the petroleum industry as either soft shales or hard shales. Soft shales are generally considered to include the plastic, gumbo, wet, hydratable and swelling shales which dissolve or disperse readily within water or aqueous fluids. Soft shales are rarely, if ever, found in formations older than Mesozoic. Hard shales, on the other hand, are hard and are substantially insoluble and nondispersible in aqueous media. They generally contain much less water and montmorillonite than-do soft shales. I-Iard shales generally occur in older, deeper formations.

Soft shales and hard shales both present serious problems during drilling operations. If soft shales are drilled with water or water-based fluids, for example, they may readily disperse or dissolve in circulating fluid to form a troublesome plastic mass. This dispersion has been generally attributed to the presence of montmorillonite in the shales. Hard shales, on the other hand, do not normally disperse in the fluid but nevertheless quickly lose their strength and break and slough. Until recently there has been no satisfactory or accepted explanation for the failure of hard shale. The extremely low permeabilities of the shales have led observers to theorize that drilling fluids can penetrate only along the bedding planes and that the failures are due to such penetration. It was also generally assumed that hard shales are nonswelling in the presence of water.

It has recently been discovered that shales, shaley sands, and similar argillaceous formations, in spite of their extremely low permeability, possess a strong attraction for water and are capable of withdrawing water from water-in-oil emulsions and other fluids with which they come in contact. This sensitivity to water is evidenced by dimensional changes in response to the absorption or desorption of water. These changes, although sometimes very slight, contribute materially to formation failure.

It has been found and disclosed in US. Ser. No. 726,693, filed May 6, 1968, that water transfer will normally occur from emulsion fluids to a shale formation when the activity of the water contained within the aqueous phase of the emulsion exceeds that of water contained within the shale. By adding vapor pressure depressants to the aqueous phase of the emulsion fluids, the transfer of water from the fluid to the argillaceous formation can be eliminated. Such a fluid can be used to drill a water-sensitive formation with little likelihood of the hole sloughing.

SUMMARY OF THE INVENTION This invention provides a method of treating a water-inoil emulsion fluid to retard migration of water from the drilling fluid to a water-sensitive formation to such an extent that formation damage will be substantially eliminated. The method of the invention comprises removing water associated with the water-in-oil emulsion fluid during drilling operations. The invention is useful in drilling a water-sensitive formation with a water-in'oil emulsion drilling fluid where the activity of the aqueous phase of this drilling fluid is greater than the activity of the formation during the drilling operation. It is also useful as a means of reducing the water activity of an invert emulsion drilling fluid to a level no greater than the activity of the formation. Broadly stated, the invention comprises removing water associated with a water-in-oil emulsion drilling fluid to reduce the water content of the aqueous phase of the drilling fluid to the level required to prevent any substantial migration of the water from the drilling fluid to the formation during the time the drilling fluid is in contact with the formation.

It has been found that the rate at which water will migrate from a particular water-in-oil emulsion fluid to a water-sensitive formation is a function of both the difference between the activity of the aqueous phase of the emulsion fluid and the water contained in the formation and of the water content of the emulsion drilling fluid. Migration of water from the drilling fluid to the formation can be eliminated by the addition of a sufficient quantity of a vapor pressure or activity depressant to the aqueous phase. Such migration of water can also be retarded by the use of an emulsion fluid having a low water content. Where low water content emulsion drilling fluid has become contaminated with water, its water content can simply be reduced, preferably by adsorption or vaporization. These methods are particularly advantageous because both the total water content and the activity of the water are simultaneously reduced because of the increase in the salt concentration caused by each of the processes.

It is still a further aspect of the invention to provide a method to monitor invert emulsion drilling fluids at the well site during drilling operations that are attended by such water removal operations so that water content and water activity can be changed to compensate for drilling fluid contaminants and the like encountered in the borehole.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 graphically depicts the percent elongation caused by exposing a series of Wolfcamp shale samples to a corresponding number of water-in-oil emulsion drilling fluids having the same activity but different water contents for a period of 10 hours.

FIG. 2 is a schematic view of a drilling mud system that includes a water removal unit.

FIG. 3 graphically depicts the percent elongation after 10 hours of a typical hard shale exposed to water-in-oil emulsion drilling fluids having different water contents and different activities.

DESCRIPTION OF THE PREFERRED EMBODIMENTS The rate of transfer of water from the aqueous phase of a water-in-oil invert emulsion drilling fluid to a water-sensitive formation with which it is in contact is a function of both the difference in activity between the aqueous phase of the emulsion and the water contained within the shale and of the overall water content of the drilling fluid. Although oil-base fluids and invert emulsion fluids, which are both water-in-oil emulsion fluids, are sometimes distinguished on the basis of water content, all three terms are treated as synonymous herein. An oil-base fluid containing no water can be considered here as a zero water content water-in-oil emulsion.

As pointed out in US. Ser. No. 726,693, if the activity of the aqueous phase of the water-in-oil emulsion fluid is substantially equal to that of the water-sensitive formation, the

rate of transfer of water from the emulsion fluid to the watersensitive formation will be substantially zero. However, in some cases a low rate of water transfer can be tolerated during the period the water-in-oil emulsion drilling fluid contacts the formation without any serious formation damage. Thus, if the activity of the emulsion fluid is only slightly greater than the activity of the water-sensitive shale. many such shales can be drilled without serious problems.

For a particular difference in activity between the aqueous phase of the drilling fluid and the formation, the rate of fluid migration is a function of the water content of the emulsion drilling fluid. Thus, if the activity of the aqueous phase of the drilling fluid is higher than that of the formation, the rate of water transfer from the drilling fluid to the formation can be significantly reduced by lowering the water content of the drilling fluid. FIG. 1 illustrates the relationship between the water content of an emulsion fluid and its rate of water transfer to a water-sensitive shale. All of the emulsion fluids tested have the same activity which is higher than that of the shale.

It has been found that the rate of elongation ofa water-sew sitive shale sample is a quantitative measure of the rate at which it is adsorbing water. Thus, the rate of water transfer is expressed in FIG. 1 as the percentage of linear swelling ob served after hours of contact between each sample of this Wolfcamp shale formation and the various drilling fluids. Although a thorough evaluation of the relationship between an invert emulsion fluid and a particular shale formation would require the use of an extended swelling test, it has been found that sufficiently accurate results to characterize individual fluids can generally be obtained by using the degree of swelling observed at the end of IO hours. A suitable exposure time for a formation can be selected from examination of the relationship between swelling and log time for a series of emulsion fluids. In those cases where the emulsion fluid shale system requires a substantial period of time to attain a constant rate of migration, a period longer than 10 hours will be desirable. FIG. 1 clearly shows that as the percentage of water in an emulsion fluid having a particular activity increases, the rate ofwater transfer also increases. The data indicate the rate of water transfer is a linear function of water content. There is, of course, no water transfer at zero water content. The slope of the line is a function of the difference in activity between the aqueous phase of the emulsion fluid and the water contained in the shale. Thus, if the activity of the emulsion fluid is balanced with that of the shale formation this linear function would be displaced downwardly to lay on the zero swelling line indicating no water transfer regardless of the water content. It will be apparent from an examination of FIG. 1 that reduction of the percent water in an emulsion fluid having an activity in excess of that of the shale formation with which it is in contact will be advantageous.

Data similar to that plotted in FIG. 1 are very useful in characterizing the behavior of a particular formation in the presence of emulsion fluids having varying water contents. These particular data were generated from preserved samples of the West Texas Wolfcamp shale formation which was exposed to an invert emulsion fluid having activity of 0.9. A strain gage apparatus similar to that disclosed in U.S.'Ser. No. 726,693 was used to measure the linear swelling as a function of time to establish the percent linear swelling of the samples. It will be found that for any particular water-sensitive formation there exists a linear swelling value corresponding to a preselected exposure time that represents an upper safe limit for drilling the formation. This upper safe limit must be established from actual drilling experience and, of course, presumes that there will not be any inordinate delay during the drilling of the well. It has been found, for example, that the Wolfcamp shale can be drilled with an emulsion fluid having a .04 percent liner swelling value after ten hours. Thus, for a water-in-oil emulsion fluid having an activity of 0.9 it can be seen from FIG. I that by maintaining the water content of the emulsion fluid at a value of 10 percent or less the shale can be drilled without any sloughing or failure. Other shales will respond in a similar fashion although they will have a different tolerance of swelling at the selected time level.

Well site equipment for removing water associated with a water-in-oil emulsion in accordance with the invention is schmetically shown in FIG. 2. A drilling string 11 having a drilling bit 13 at its lower end is shown suspended in borehole 15. The emulsion mud is withdrawn from tank l7 by pump l9 through suction line 21. The pump forces the drilling fluid through conduit 22 to the upper end of drilling string II. The drilling fluid is circulated down the drill string and through bit 13 where it cleans the bottom of borehole 15. The fluid returns to the surface through annulus 23 where it passes out mud return line 25 into water removal unit 27.

The water removal unit may be a vaporization unit. Such a unit may contain heating coils which could be gas fired, oil

fired or electrically energized and which would increase the temperature of the emulsion fluid to a high enough level to vaporize the water. Typically, the oil contained within the emulsion drilling fluid will have a boiling point in the range of 400 to 750F.,- whereas water will boil at around 212F. The unit could therefore be operated at a temperature on the order of 300F. quite satisfactorily. In deep wells formation temperatures in the range of 400F. are often encountered. In such wells, very little additional heating would be necessary in order to release the water contained in the emulsion fluid when it arrives at the vaporization unit. After distillation the emulsion fluid gravitates from water removal unit 27 to storage tank 17 via conduit 29. Storage tank 17 is open to the atmosphere and additional water will evaporate while the heated fluid is retained in the storage tank. If retention time is not long enough to properly cool the fluid before it is pumped back into the hole, a cooling tower or other cooling means may be required.

The water removal unit could also be an adsorption unit. It. should be charged with a dessicant which will not be affected by the external oil phase of the emulsion and which will not alter the rheological properties of the drilling fluid. Solid dessicants such as calcium chloride, bentonite or the like will be found to be suitable. A heater can be used to regenerate the dessicant. After dehydration the drilling fluid gravitates from the water removal unit to storage tank 17.

It will be found to be advantageous to monitor the drilling fluid during drilling operations so as to maintain the aqueous phase such that it will not damage the formation. Whenever the amount of water contained in the emulsion fluid becomes excessive, the vaporization unit can be actuated to reduce water content to the desired level. FIG. 3 graphically presents percent linear swelling at 10 hours versus percent water in the emulsion fluid for a typical series of emulsion fluids having different activities placed in contact with a hypothetical hard shale. Line A-1 has an activity of 1.0 (fresh water), line A-Z has an activity of 0.9, and line A-3 has an activity ofO.8. Thus, lines A1, A-2, and A-3 represent invert emulsion drilling fluids having successively lower activities, while the abscissa itself represents an aqueous phase activity equal to that of the formation. Such data can be prepared from a series of shale swelling tests run with invert emulsions of varying water contents and varying activities in accordance with Ser. No. 726,693. A horizontal line is drawn at the 10 hour linear swelling level of 0.04 percent. This represents a safe swelling level for the hypothetical shale, and safe drilling can be sustained as long as the condition of the fluid is maintained below this line. For example, point number one (1) falls on line A-2 and corresponds to a fluid having a water content of 10 percent and an activity of 0.9. This composition has a linear swelling percentage of .04 and is thus safe for drilling the shale. Point two (2) falls on line A-3 and thus corresponds to a water-in-oil emulsion fluid having an aqueous phase activity of 0.8 and a water content of 24 percent. It, however, would exhibit a .04 percent linear swelling at 10 hours and so can be considered safe for drilling. It can thus be seen that a higher water content can be sustained safely if the activity of the fluid is reduced. Point three (3) shown on line A-l represents an unsafe drilling condition at a 14 percent water content. It will have a .14 percent swelling at hours. To recondition this fluid for safe drilling, a vapor pressure depressant could be added in accordance with Ser. No. 726,693; this would lower the rate of swelling without changing the water content from 14 percent. This change of composition would follow the path illustrated by line 3-3. Alternatively, the vaporization or adsorption system may be used to reduce the amount of water down to 4 percent which will reestablish a safe swelling rate as is shown by line 3-3. The activity of the fresh water aqueous phase remains at 1.0.

Point 4 corresponds to a fluid having an activity of 0.9 and a water content of percent. This fluid indicates a l0 hour linear swelling level of 0.085 percent and thus would be unsafe for drilling. vaporization or adsorption of excess water would cause the fluid composition to follow the path of line 4-4. This represents the effect vaporization or adsorption have on a fluid that has been contaminated but which contains a certain amount of a vapor pressure depressant. As water is removed from the internal phase of the emulsion fluid, the concentration of the vapor pressure depressant is increased thereby lowering the activity of the drilling fluid at the same time the water content is reduced.

To determine the condition of the drilling fluid during drilling operations without actually conducting a 10 hour swelling test a hygrometer can be used. The hygrometer is used to measure the relative humidity of the water vapor in equilibrium with a sample of the emulsion fluid which is a measure of the activity of the emulsion drilling fluid. A water content test can be run on a separate sample by breaking the emulsion. Knowing both the activity and the water content of the emulsion fluid, the condition of the fluid can be determined from FIG. 3. It can thus be readily determined whether the drilling fluid is properly conditioned to drill through the water-sensitive shale or whether additional vaporization is necessary for continued drilling.

One convenient method for establishing the maximum safe level of swelling for a particular shale formation is to vary the water content of a water-in-oil emulsion drilling fluid while drilling through the troublesome formation. The starting point should correspond to a slow rate of migration such as would be caused by using a mud with a water content of 1 percent or less. As the water content is increased a point will be reached where shale sloughing will begin. Water content should then be decreased until a level is found that will eliminate degradation of the borehole. By measuring the water content and water activity of the drilling fluid the corresponding maximum safe swelling level can be determined from a plot similar to FIG. 3. It will be apparent that this maximum safe level can also be determined by varying the activity of the aqueous phase of the drilling fluid.

We claim:

1. In a method of drilling a well in a water-sensitive formation with a water-in-oil emulsion drilling fluid wherein the aqueous activity of said drilling fluid is greater than the aqueous activity of said formation during drilling. the improvement which comprises removing water associated with the drilling fluid to the extent necessary to reduce the aqueous activity of the drilling fluid to a level that is substantially no greater that the activity of the formation without breaking said water-in-oil emulsion and thereafter circulating said drilling fluid in said well.

2. The method defined in claim 1 wherein said water is removed by vaporizing it from said drilling fluid.

3. The method defined in claim 1 wherein said water is removed by adsorbing it from said drilling fluid.

4. [n a method of drilling a well in a water-sensitive formation with a water-in-oil emulsion drilling fluid wherein the aqueous activity of said drilling fluid is greater than the aqueous activity of said formation during drilling, the improvement which comprises removing water associated with the drilling fluid to the extent necessary to reduce the water content and aqueous activity of the drilling fluid to levels required to prevent any substantial migration of water from the drilling fluid to the formation without breaking said water-in-oil emulsion, the aqueous activity of said drilling fluid remaining greater than that of said formation, and thereafter circulating said drilling fluid in said well.

5. The method defined in claim 4 wherein said water is removed by vaporizing it from said drilling fluid.

6. The method defined in claim 4 wherein said water is removed by adsorbing it from said drilling fluid.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION October 13, 1970 Patent No. 3,533,480 Dated Inventor) Martin E. Chenevert and Joseph A. Polasek rs in the above-identified patent It is certified that error appea and that said Letters Patent are hereby corrected as shown below:

In the bibliographic data, add

[22] Filed July 16, 1968 [45] Patented October 13, 1970 Signed and sealed this 3rd day of October 1972.

(SEAL) Attest:

ROBERT GOT'ISCHALK EDWARD M.FLI11TCHER, JR. Attesting, Officer' Commissioner of Patents 

